Heavy hydrocarbons, e.g. bitumen; represent a huge natural source of the world's total potential reserves of oil. Present estimates place the quantity of heavy hydrocarbon reserves at several trillion barrels, more than 5 times the known amount of the conventional, i.e. non-heavy, hydrocarbon reserves. This is partly because heavy hydrocarbons are generally difficult to recover by conventional recovery processes and thus have not been exploited to the same extent as non-heavy hydrocarbons. Heavy hydrocarbons possess very high viscosities and low API (Americal Petroleum Institute) gravities which makes them difficult, if not impossible, to pump in their native state. Additionally heavy hydrocarbons are characterised by high levels of unwanted compounds such as asphaltenes, trace metals and sulphur that need to be processed appropriately during recovery and/or refining.
Some methods have been developed to extract and process heavy hydrocarbon mixtures. The method that is used most often commercially today for heavy hydrocarbon recovery from subterranean reservoirs is steam assisted gravity drainage (SAGD). In this method two horizontal wells are drilled approximately five meters apart then steam is injected into the reservoir through the upper wellbore permeating the oil sand. Steam softens the heavy hydrocarbon (e.g. bitumen) and enables it to flow out of the reservoir and into the lower well. From there it is pumped to the surface facilities. Significant improvements have been made in SAGD processes in recent years, and further optimizations continue to be driven by cost and environmental issues. These improvements include more efficient methods for steam generation and a general, reduction in the steam to bitumen ratio. Both of these improvements are aimed at reducing the amount of steam that needs to be produced which is an energy consuming process that also generates vast amounts of CO2. Another recent development has been the injection of about 10% solvents (sometimes called diluents) with the steam. The idea of this improvement is that the diluent condenses and mixes into the hydrocarbon in the formation and thereby decreases its viscosity and increases its API gravity and thus enhances its recovery.
Nevertheless the SAGD process still suffers from inherent drawbacks. These include:    (i) the use of natural gas for steam generation causes high CO2 emissions    (ii) diluent must still be added to transport the recovered hydrocarbon to refineries users and then separated therefrom. The latter causes CO2 emissions    (iii) asphaltenes are present in the recovered hydrocarbon and their removal at refineries causes yet further CO2 emissions.
Overall the SAGD process leads to the production of vast amounts of CO2 whereas it has already been recognised in the energy industry that CO2 emissions must be managed better. The concentration of CO2 in the Earth's atmosphere has already risen from about 280 to 370 parts per million since the industrial revolution and if current trends are not changed may reach at least twice the preindustrial level by 2100. The possible environmental impact of such a change is well documented.
More recently a number of in situ combustion bitumen recovery processes have been developed and a few of these are in the pilot plant phase. In these methods the injection and production wells are only preheated using steam. Once the oil sands reservoir has been heated to a sufficient ignition temperature, air is injected into the injection wells and ignites to ultimately form a combustion front driving the bitumen recovery. Hot combustion gases contact the bitumen ahead of the combustion zone and heat the bitumen to temperatures greater than about 300 to 400° C. An example of such a process is described in U.S. Pat. No. 5,456,315.
In the method disclosed in U.S. Pat. No. 5,456,315 a row of vertical injection wells are completed in the upper part of the reservoir, at least one gas production well, spaced laterally from the row of injection wells, is also provided and a horizontal production well is positioned below the injection interval. Oxygen-containing gas, typically air, is injected through each injection well and ignites. Initially a discrete combustion chamber exists around the base of each injection well but as combustion proceeds a common combustion chamber forms between each of the injection wells. The combustion zone or area has fronts comprising hot gases that serve to heat up hydrocarbon in their vicinity. This results in the production of heated heavy hydrocarbon of lower viscosity than the native hydrocarbon that drains downwardly through the chamber under the influence of gravity. Thus hydrocarbon is produced from the horizontal production well lying below the injection interval. The gases produced from the in situ combustion flow through the reservoir toward the gas production wells.
This process, however, also suffers from a major disadvantage. Air is the preferred gas for injection into the well to establish and maintain combustion, thus vast quantities of nitrogen-containing compounds including NOx gases are produced in the combustion gases along with CO2. These have to be removed from the gases produced from the gas production wells in order for it to be disposed which is an expensive process. Moreover, as with SAGD, significant volumes of CO2 are simply emitted into the atmosphere.
U.S. Pat. No. 4,410,042 and U.S. Pat. No. 4,498,537 disclose modified in situ combustion methods wherein oxygen or a mixture of oxygen and CO2 is used instead of air as the oxidant for combustion. U.S. Pat. No. 4,410,042 discloses a method wherein combustion is initiated with a mixture of CO2 and O2 but after the combustion front has advanced away from the wellbore, the CO2/O2 mixture is replaced with pure O2. The method is designed to reduce the risk of ignition in the wellbore. U.S. Pat. No. 4,498,537 discloses a method wherein pure O2 or a CO2/O2 mixture containing at least 75% O2 is used. It teaches that the use of oxygen or an O2/CO2 mixture is advantageous because the increased levels of CO2 produced in the reservoir acts as a local pressurising agent as well as a solvent in the oil phase to lower the viscosity of the oil, which together with the thermal effects of combustion, stimulates the reservoir and increases the production of oil.
Compared to the method disclosed in U.S. Pat. No. 5,456,315, however, even greater concentrations of CO2 are produced in the processes of U.S. Pat. No. 4,410,042 and U.S. Pat. No. 4,498,537 and are simply emitted to the atmosphere. As mentioned above, the increase in CO2 levels in the Earth's atmosphere is a growing environmental concern and many options are currently being explored to reduce its production. Considerable attention is, for example, being focussed on energy generation from alternative energy sources such as solar and wind power. However about 85% of the world's present energy needs are still met by burning fossil fuels therefore technologies are still needed that enable hydrocarbons to be recovered and then utilised more efficiently and with lower environmental impact, in particular, with the release of less CO2.
In particular a need exists for recovery processes for hydrocarbon mixtures, and especially heavy hydrocarbon mixtures, that enables the CO2 produced to be managed. In particular, methods are required that reduce the CO2 emitted to the atmosphere compared to currently available techniques. Methods resulting in superior feedstock for delivery to refineries would of course also be advantageous.
The present inventors have devised an in situ combustion process wherein an oxygen-rich gas, for instance, a mixture of oxygen and CO2, is used for the injection that generates and maintains combustion in the reservoir. This generates the hot combustion gases that serve to soften the heavy hydrocarbon and ease its recovery. A CO2-rich atmosphere is simultaneously created during combustion from which the CO2 can easily be captured and optionally recycled and/or stored. Consequently little, if any, CO2 is emitted into the Earth's atmosphere.